A seismic survey represents an attempt to map the subsurface of the earth by sending sound energy down into the ground and recording the "echoes" that return from the rock layers below. The source of the down-going sound energy might come, for example, from explosions or seismic vibrators on land, or air guns in marine environments. During a seismic survey, the energy source is placed at various locations near the surface of the earth above a geologic structure of interest. Each time the source is activated, it generates a seismic signal that travels downward through the earth, is reflected, and, upon its return, is recorded at a great many locations on the surface. Multiple explosion/recording combinations are then combined to create a nearly continuous profile of the subsurface that can extend for many miles. In a two-dimensional (2D) seismic survey, the recording locations are generally laid out along a single line, whereas in a three dimensional (3D) survey the recording locations are distributed across the surface in a grid pattern. In simplest terms, a 2D seismic line can be thought of as giving a cross sectional picture (vertical slice) of the earth layers as they exist directly beneath the recording locations. A 3D survey produces a data "cube" or volume that is, at least conceptually, a 3D picture of the subsurface that lies beneath the survey area. In reality, though, both 2D and 3D surveys interrogate some volume of earth lying beneath the area covered by the survey.
A seismic survey is composed of a very large number of individual seismic recordings or traces. In a typical 2D survey, there will usually be several tens of thousands of traces, whereas in a 3D survey the number of individual traces may run into the multiple millions of traces. Chapter 1, pages 9-89, of Seismic Data Processing by Ozdogan Yilmaz, Society of Exploration Geophysicists, 1987, contains general information relating to conventional 2D processing and that disclosure is incorporated herein by reference. General background information pertaining 3D data acquisition and processing may be found in Chapter 6, pages 384-427, of Yilmaz, the disclosure of which is also incorporated herein by reference.
A modern seismic trace is a digital recording (analog recordings were used in the past) of the acoustic energy reflecting back from inhomogeneities or discontinuities in the subsurface, a partial reflection occurring each time there is a change in the elastic properties of the subsurface materials. The digital samples are usually acquired at 0.002 second (2 millisecond or "ms") intervals, although 4 millisecond and 1 millisecond sampling intervals are also common. Each discrete sample in a digital seismic trace is associated with a travel time, and in the case of reflected energy, a two-way travel time from the surface to the reflector and back to the surface again. Further, the surface location of the shot-receiver combination that gave rise to each seismic trace is carefully tracked during acquisition and is often made a part of the trace itself, where it can be accessed as needed during subsequent processing steps. One important use for this information arises when an explorationist correlates the seismic reflections with specific surface and subsurface locations, i.e. when he or she posts and/or contours seismic data values--and attributes extracted therefrom--on a map (i.e., "mapping").
The data in a 3D survey are amenable to viewing in a number of different ways. First, horizontal "constant time slices" may be extracted from a stacked or unstacked seismic volume by collecting all of the digital samples that occur at the same travel time. This operation results in a 2D horizontal plane of seismic data. By animating a series of these 2D planes, it is possible for the interpreter to pan through the volume, giving the impression that successive layers are being stripped away so that the information that lies underneath may be observed. Similarly, a vertical plane of seismic data may be taken at an arbitrary azimuth through the volume by collecting and displaying the seismic traces that lie along a particular line. This operation, in effect, extracts an individual 2D seismic line from within the 3D data volume.
Seismic data that have been properly acquired and processed can provide a wealth of information to the explorationist, one of the individuals within an oil company whose job it is to locate potential drilling sites. For example, a seismic profile gives the explorationist a broad view of the subsurface structure of the rock layers and often reveals important features associated with the entrapment and storage of hydrocarbons and other subsurface resources, including features such as faults, folds, anticlines, unconformities, and sub-surface salt domes and reefs, among many others. During the computer processing of seismic data, estimates of subsurface rock velocities are routinely generated and near surface inhomogeneities are detected and displayed. In some cases, seismic data can be used to directly estimate rock porosity, water saturation, and hydrocarbon content. Less obviously, seismic waveform attributes such as phase, peak amplitude, peak-to-trough ratio, and a host of others, can often be empirically correlated with known hydrocarbon occurrences and that correlation applied to seismic data collected over new exploration targets.
Speaking in broad generalities, seismic energy propagates through the earth in one of two forms: compressional or "P" waves and shear or "S" waves, either of which might be generated by a wide variety of seismic sources. "Converted waves" are those waves that travel first as one type of wave and then the other, the conversion between wave-types happening at any seismic discontinuity. If the conversion happens once only, from an incident P-wave to a reflected S-wave, this mode will be called a C-wave. In anisotropic media, each such conversion will reflect both fast and slow shear waves, which modes may be termed fast and slow C-modes, respectively. Flat-lying polar anisotropic ("VTI") layers give rise to only one C-mode reflection (polarized in-line).
This conversion between P and S waves is predicted theoretically and has also been observed in practice. Although any seismic experiment generates generous amounts of such converted waves, ordinary techniques of seismic signal reception and processing are designed to suppress these waves in favor of pure-mode (e.g., P-wave) arrivals.
Nonetheless, there are many exploration and exploitation settings wherein one would wish to maximize--rather than to suppress--converted-wave arrivals, e.g., where the target cannot be readily imaged by P-waves. This might happen, for example, where the elastic contrasts of the subsurface rock layers yield only weak P-reflections; where salt bodies occur above the target; or, where subsurface "gas clouds" or gas "plumes" obscure the target, as might occur in connection with a hydrocarbon reservoir, above which the overburden contains a small concentration of gas. In this later situation, the gas may severely delay and attenuate conventional P-waves traveling through the overburden, so that the underlying reservoir will be poorly imaged on a "P" section. However, a gas-filled rock unit does not unduly slow or attenuate shear waves, so one might hope to be able to obtain better images of such reservoirs using conventional pure-mode S-wave techniques. Of course, if the seismic target lies offshore, a complication arises because shear waves do not travel through liquids, a fact which makes their generation and recording problematic. In that case, however, converted waves in combination with ocean bottom multicomponent receivers can make practical the recording of shear energy reflecting from water covered exploration targets.
Conventional seismic processing relies heavily on a stack (or average) of seismic traces from a common midpoint ("CMP", hereinafter) gather to reduce coherent and incoherent noise in the seismic section, and as a tool for estimating subsurface velocities (e.g., via constant velocity stacks). The stacking approach is generally satisfactory for single mode seismic data, but often fails when applied to converted mode data. One reason for this is that the travel paths of the converted mode waves are asymmetrical, even for simple horizontally layered media. Multiple coverage of the same subsurface point cannot be achieved for C-mode (i.e., converted mode) data by stacking a CMP gather, but instead requires true common reflection point ("CRP", hereinafter) sorting which, for C-mode reflections, is actually a common conversion point gather (a "CCP" gather, hereinafter). In brief, the standard methods used to form converted mode CCP gathers in the past have been generally unsatisfactory.
The standard method for processing C-mode data into interpretable seismic sections and volumes is founded on the assumption that the subsurface is a homogeneous isotropic medium (cf., Tessmer and Behle, 1988, "Common Reflection Point Data-Stacking Technique for Converted Waves", Geophysical Prospecting, 36, 671-688, the disclosure of which is incorporated herein by reference). To the extent that this assumption is incorrect, conventionally processed seismic data will yield a less than accurate representation of that subsurface. As might be expected, interpretations that are based on inaccurate images will also be suspect and could ultimately contribute to the drilling of a dry hole. Of course, the homogeneity assumption is not realistic in many exploration areas and, in fact, the subsurface rock units have often proven to be both inhomogeneous and anisotropic.
Thus, there is a real need for a method of processing converted mode seismic data that can accommodate inhomogeneous, anisotropic layered media. Additionally, the method should provide simple closed-form expressions that make possible hyperbolic and post-hyperbolic moveout removal, and computation of the conversion-point offset for the same sort of media. Accordingly, it should now be recognized, as was recognized by the present inventor, that there exists, and has existed for some time, a very real need for a method of seismic data processing that would address and solve the above-described problems.
Before proceeding to a description of the present invention, however, it should be noted and remembered that the description of the invention which follows, together with the accompanying drawings, should not be construed as limiting the invention to the examples (or preferred embodiments) shown and described. This is so because those skilled in the art to which the invention pertains will be able to devise other forms of this invention within the ambit of the appended claims.